The oil and gas industry desires to efficiently obtain and process hydrocarbons into desired products. These processes generally involve the use of thermal changes and/or pressure changes to separate the hydrocarbons in various stages. In particular, the processing may be performed in an oil refinery, which converts or separates the hydrocarbons (e.g., crude oil) into different streams, such as gases, light naphtha, heavy naphtha, kerosene, diesel, atmospheric gas oil, asphalt, petroleum coke and heavy hydrocarbons. Similarly, if the processing is performed in a natural gas refinery, the natural gas may be converted into industrial fuel gas, ethane, propane, butanes and pentanes.
In conventional facilities, different units separate the hydrocarbons into the desired streams. These units may include an atmospheric distillation unit, a vacuum distillation unit, a delayed coker, a hydrotreater, a merox treater, an isomerization unit, a catalytic reformer, a fluid catalytic cracker, an amine treater, a hydrocracker, and a pyrolysis unit, such as a regenerative reactor or steam cracker. Typically, the hydrocarbon stream is passed through the atmospheric distillation unit to divide the hydrocarbons (e.g., crude oil) into gases, naphtha (e.g., light naphtha and heavy naphtha), kerosene/jet fuel, diesel oil, atmospheric gas oil and atmospheric resid or bottoms. As an example, the volume amounts of these separated products or streams may be gases of 5 weight percent (wt %), naphtha of 20 wt % to 30 wt %, kerosene/jet fuel 5 wt % to 20 wt %, diesel oil of 15 wt % to 20 wt %, atmospheric gas oil of 20 wt % to 30 wt %, and atmospheric resid or bottoms of 5 wt % to 20 wt %. Each of the different percentages being a specific portion of the hydrocarbon feed. The amount of these different products may vary based on the different crude oil provided for processing in the system. Some other conventional refinery facilities may also include a vacuum distillation unit, a hydrotreater, a merox treater, a delayed coker, a fluid catalytic cracker and a hydrocracker, which are used to further separate products, such as light vacuum gas oil, heavy vacuum gas oil and vacuum residuum.
Once the hydrocarbons have been separated, pyrolysis units are typically used to further process certain of the hydrocarbon streams to produce olefins. Olefins are the basic building block for other petrochemical products, which may be utilized to produce other products. As a specific example, a pyrolysis unit may be a steam cracking furnace that may convert ethane into ethylene and other byproducts. The ethylene may be separated from the by products and further processed into polyethylene or other products.
As part of the processing of the hydrocarbon stream, the hydrocarbons may have to be transported via conduits and/or pipes to the pyrolysis unit. That is, the hydrocarbon stream may be provided via a pipeline to the facility or via conduits and/or pipes at another location within the facility. As an example, if the hydrocarbon stream is an ethane stream, it may be transported via a pipeline grid system at high pressure (e.g., about 900 psig (pounds per square inch gauge) (6205 kilopascal gauge (kPag)) in the super critical state. This high pressure ethane stream may also be referred to as dense phase ethane. If the hydrocarbon stream is provided at this higher pressure, it may have to be depressurized prior to being fed to a pyrolysis unit.
While some hydrocarbon processes use methanol in cold environments to remove hydrates (e.g., referred to as deriming), conventional processes for transporting hydrocarbons and depressurizing the hydrocarbons upstream of a pyrolysis unit do not utilize hydrate suppression to manage the hydrates. Commonly, the higher pressure hydrocarbon streams are either vaporized using low pressure steam prior to being provided to a pyrolysis unit or the processes utilize driers to remove the water from the hydrocarbon stream before letting down in pressure, which reduces the temperature of the hydrocarbon stream. The removal of the water prevents freezing problems and hydrate formation, as the temperature may be below the hydrate formation point for the hydrocarbon stream. Hydrates are solid crystalline products, which form when water encages hydrocarbon molecules, such as ethane. In certain instances, hydrates may form at temperatures well above the freezing point of water. As an example, for ethane, the initial hydrate formation point is between 60° F. (15.5° C.) and 65° F. (18.3° C.), which is dependent upon the specific pressure. Similar to ice formed from water, hydrates from the hydrocarbon stream may plug pipelines and other process equipment resulting in shutdowns and other operational problems.
Hydrate suppression is commonly used in the processing of natural gas liquid (NGL). See Gas Conditioning and Processing, Volume 1: The Basic Principles, by John M. Campbell. In natural gas liquid processes, the wet natural gas is cooled to separate the dry natural gas from water. The hydrate inhibitor enables operating at colder temperatures than the stream alone. This process utilizes cooling of the natural gas liquid stream to assist the separation, which is not useful in the proposed process.
What is needed is a method for managing hydrate formation in a hydrocarbon stream for a pyrolysis unit, such as a steam cracking furnace or a regenerative reverse flow reactor. In particular, it may be desirable to construct a system that manages a hydrocarbon stream for a pyrolysis unit in more efficient manner, which manages the hydrate formation through the process.